Sweet 16 Gassers: Stifel's update on the U.S. ngas market
Posted: Wed Dec 09, 2020 2:28 pm
Stifel's update on natural gas prices 12-9-2020
Oil & Gas Exploration and Production
Fundamental tenants of our natural gas bull thesis remain intact by Derrick Whitfield, an energy sector analyst at Stifel
"Front-month natural gas prices have declined by ~28% over the past five weeks due to unexpectedly warm weather. Based on heating degree days, the first month of withdrawal season was 22% below the 10-year average. With this backdrop, we see three debates driving the near-to-medium-term natural gas trade.
First, is natural gas an all or nothing trade based on oil macro?
Second, can natural gas work if the entire winter follows the November trend?
Third, can the Permian and Appalachia maintain their strong Q4 production trajectories?
In short, we believe the fundamentals tenants (associated gas decline, Appalachian producers' capital discipline, supportive export market) of our bull thesis on natural gas remain in-tact. While a warm winter could delay our bullish thesis, we still project significant undersupply in 2021 and beyond. Furthermore, lower prices from a warm winter would further pressure supply in 2021 and strengthen the bull case for 2022."
MY TAKE: Add the fact that U.S. natural gas exports are about 2 Bcfpd higher than the forecasts that I saw less than two months ago. LNG exports are running at 11 Bcfpd when I thought our export capacity was 10 Bcfpd. Exports via pipeline to Mexico are up over a Bcfpd YOY as well. All the gassers want for Christmas is a Polar Vortex.
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More details from the Stifel Report: My comments in blue.
Can natural gas work if we assume the entire winter follows the current November trend?
• The EIA estimates there were 413 Heating Degree Days (HDDs) in the U.S. through November, ~22% below the 10-year average. We estimate
demand would drop by an average of 6.5 Bcfpd or 17% over the winter if we assume the entire winter follows the November trend. < Basing the entire winter forecast on a warm November is an extremely conservative assumption. November is seldom a preview of Q1 weather.
• As winter weather poses an inherent risk to our forecasts, we encourage investors to test extreme cases on both sides to identify opportunities.
Assuming 2020/2021 and 2021/2022 winters will be roughly equal to the warmest winter in the last decade, we estimate the market would be
oversupplied by 0.3 Bcfpd from Q420-Q321 and undersupplied by 2.5 Bcfpd from Q421-Q322. Conversely, if we estimate a normal winter for
2020/2021 and the coldest winter in the last decade for 2021/2022, we estimate the market would be undersupplied by 1.5 Bcfpd from Q420-
Q321 and 6.5 Bcfpd from Q421-Q322. Under the most negative scenario over the past decade, we estimate currently messaged activity levels are
insufficient to balance the market for 2022.
Can the Appalachian and Permian maintain their strong Q4 production trajectories?
• In addition to a warmer than expected start to the winter, we have observed stronger than expected pipeline flows in the Appalachian and Permian.
In short, we do not believe the Appalachian and Permian can maintain their strong Q4 production trajectories. < Raymond James also estimates that Permian Basin gas production will decline in 1H 2021.
• The surge in Appalachian Q420 pipeline flows was driven by the resumption of curtailed volumes at elevated pressures. In speaking with industry,
the expectation is for 1-2 months of flush volumes from the resumption of curtailed volumes. Beyond that period, we project Appalachian production
to moderate based on two developments.
> First, we expect industry to focus on corporate returns and fixing their balance sheets versus growing
production. There is $27.2 billion of debt due between 2021-2025.
> Second, the majority of Appalachian operators are messaging maintenance capital scenarios for 2021.
In light of the recent pullback in natural gas prices and the substantial amount of productive
capacity that is tied up in M&A and/or bankruptcy proceedings, we expect Appalachian production to decline over the coming quarters.
• The surge in Permian 2H20 pipeline flows in New Mexico appears to be driven by a confluence of operational factors. As shown in Figure 8, the
industry is generally allocating more capital to New Mexico than Texas within the Delaware Basin and more capital to Eddy County than Lea County
within the New Mexico portion of the Delaware. While the net effect of these allocation decisions is more gas, we do not believe the industry is
deliberately chasing higher GOR areas for the benefit of advantaged gas pricing based on our conversations with the relevant management teams.
In short, we believe the increase in gas production is driven by three operational considerations including: i) resource capture on federal lands, ii)
enhanced economics on federal lands (lower royalty burden), and iii) less flaring (~0.2-0.3 Bcfpd impact). Assuming these developments remain in
play for 2021-2022, our Permian production is biased higher by ~0.2 / 0.3 Bcfpd in 2021 / 2022.
Associated gas declines and resilient natural gas demand continue to underpin our bull thesis.
> Regarding natural gas demand, we acknowledge weather plays a pivotal role in residential and commercial segments; however,
we estimate increasing LNG export capacity and arbitrage opportunities and the shift from coal to natural gas for
electric power generation will provide structural support.
>Regarding natural gas supply, we estimate the recent shift to lower activity levels in oil-weighted basins and the chronic
underinvestment in gas-weighted basins will result in a declining natural gas production base that will require significant
investment to reverse. Specifically, we estimate a natural gas price of ~$3.25/mcf would be required to balance the market in
2022, assuming sufficient takeaway capacity and shareholders' willingness to accept higher activity levels.
> While a warm winter could delay our bullish gas thesis, we are still modeling significant undersupply in 2021 and beyond.
Furthermore, lower gas prices resulting from a warm winter would further pressure supply in 2021 and strengthen the bull case
for 2022.
----------------------------
All four "gassers" in the Sweet 16 (AR, CRK, EQT and RRC) have a very high percentage of their Q4 natural gas hedged, therefore the recent dip in gas prices will have very little impact on their Q4 revenues. On the other hand they have very little of their NGLs hedged. NGL prices have firmed up nicely. The production mix for each company is shown at the bottom of each company's forecast/valuation model. You can find all of them under the Sweet 16 tab.
Oil & Gas Exploration and Production
Fundamental tenants of our natural gas bull thesis remain intact by Derrick Whitfield, an energy sector analyst at Stifel
"Front-month natural gas prices have declined by ~28% over the past five weeks due to unexpectedly warm weather. Based on heating degree days, the first month of withdrawal season was 22% below the 10-year average. With this backdrop, we see three debates driving the near-to-medium-term natural gas trade.
First, is natural gas an all or nothing trade based on oil macro?
Second, can natural gas work if the entire winter follows the November trend?
Third, can the Permian and Appalachia maintain their strong Q4 production trajectories?
In short, we believe the fundamentals tenants (associated gas decline, Appalachian producers' capital discipline, supportive export market) of our bull thesis on natural gas remain in-tact. While a warm winter could delay our bullish thesis, we still project significant undersupply in 2021 and beyond. Furthermore, lower prices from a warm winter would further pressure supply in 2021 and strengthen the bull case for 2022."
MY TAKE: Add the fact that U.S. natural gas exports are about 2 Bcfpd higher than the forecasts that I saw less than two months ago. LNG exports are running at 11 Bcfpd when I thought our export capacity was 10 Bcfpd. Exports via pipeline to Mexico are up over a Bcfpd YOY as well. All the gassers want for Christmas is a Polar Vortex.
---------------------
More details from the Stifel Report: My comments in blue.
Can natural gas work if we assume the entire winter follows the current November trend?
• The EIA estimates there were 413 Heating Degree Days (HDDs) in the U.S. through November, ~22% below the 10-year average. We estimate
demand would drop by an average of 6.5 Bcfpd or 17% over the winter if we assume the entire winter follows the November trend. < Basing the entire winter forecast on a warm November is an extremely conservative assumption. November is seldom a preview of Q1 weather.
• As winter weather poses an inherent risk to our forecasts, we encourage investors to test extreme cases on both sides to identify opportunities.
Assuming 2020/2021 and 2021/2022 winters will be roughly equal to the warmest winter in the last decade, we estimate the market would be
oversupplied by 0.3 Bcfpd from Q420-Q321 and undersupplied by 2.5 Bcfpd from Q421-Q322. Conversely, if we estimate a normal winter for
2020/2021 and the coldest winter in the last decade for 2021/2022, we estimate the market would be undersupplied by 1.5 Bcfpd from Q420-
Q321 and 6.5 Bcfpd from Q421-Q322. Under the most negative scenario over the past decade, we estimate currently messaged activity levels are
insufficient to balance the market for 2022.
Can the Appalachian and Permian maintain their strong Q4 production trajectories?
• In addition to a warmer than expected start to the winter, we have observed stronger than expected pipeline flows in the Appalachian and Permian.
In short, we do not believe the Appalachian and Permian can maintain their strong Q4 production trajectories. < Raymond James also estimates that Permian Basin gas production will decline in 1H 2021.
• The surge in Appalachian Q420 pipeline flows was driven by the resumption of curtailed volumes at elevated pressures. In speaking with industry,
the expectation is for 1-2 months of flush volumes from the resumption of curtailed volumes. Beyond that period, we project Appalachian production
to moderate based on two developments.
> First, we expect industry to focus on corporate returns and fixing their balance sheets versus growing
production. There is $27.2 billion of debt due between 2021-2025.
> Second, the majority of Appalachian operators are messaging maintenance capital scenarios for 2021.
In light of the recent pullback in natural gas prices and the substantial amount of productive
capacity that is tied up in M&A and/or bankruptcy proceedings, we expect Appalachian production to decline over the coming quarters.
• The surge in Permian 2H20 pipeline flows in New Mexico appears to be driven by a confluence of operational factors. As shown in Figure 8, the
industry is generally allocating more capital to New Mexico than Texas within the Delaware Basin and more capital to Eddy County than Lea County
within the New Mexico portion of the Delaware. While the net effect of these allocation decisions is more gas, we do not believe the industry is
deliberately chasing higher GOR areas for the benefit of advantaged gas pricing based on our conversations with the relevant management teams.
In short, we believe the increase in gas production is driven by three operational considerations including: i) resource capture on federal lands, ii)
enhanced economics on federal lands (lower royalty burden), and iii) less flaring (~0.2-0.3 Bcfpd impact). Assuming these developments remain in
play for 2021-2022, our Permian production is biased higher by ~0.2 / 0.3 Bcfpd in 2021 / 2022.
Associated gas declines and resilient natural gas demand continue to underpin our bull thesis.
> Regarding natural gas demand, we acknowledge weather plays a pivotal role in residential and commercial segments; however,
we estimate increasing LNG export capacity and arbitrage opportunities and the shift from coal to natural gas for
electric power generation will provide structural support.
>Regarding natural gas supply, we estimate the recent shift to lower activity levels in oil-weighted basins and the chronic
underinvestment in gas-weighted basins will result in a declining natural gas production base that will require significant
investment to reverse. Specifically, we estimate a natural gas price of ~$3.25/mcf would be required to balance the market in
2022, assuming sufficient takeaway capacity and shareholders' willingness to accept higher activity levels.
> While a warm winter could delay our bullish gas thesis, we are still modeling significant undersupply in 2021 and beyond.
Furthermore, lower gas prices resulting from a warm winter would further pressure supply in 2021 and strengthen the bull case
for 2022.
----------------------------
All four "gassers" in the Sweet 16 (AR, CRK, EQT and RRC) have a very high percentage of their Q4 natural gas hedged, therefore the recent dip in gas prices will have very little impact on their Q4 revenues. On the other hand they have very little of their NGLs hedged. NGL prices have firmed up nicely. The production mix for each company is shown at the bottom of each company's forecast/valuation model. You can find all of them under the Sweet 16 tab.